Hydraulic fracturing is a process that creates fractures in rock formations (or reservoirs), which has the effect of increasing the output of a well. The most important industrial use of this process is for stimulating oil and gas wells. Natural fracturing includes volcanic dikes and sills and frost weathering. Man-made fractures are commonly extended into targeted rock formations and are typically created using wellbores drilled into the formations to enhance oil and natural gas recovery, such as from coal beds and shale rock, etc.
Hydraulic fractures are typically extended by creating internal fluid pressure into the formations which opens the fractures and causes them to extend through the formations. The fracture width is typically maintained by introducing a proppant, such as sand, ceramic, or other particulates, wherein the imposition of the proppant into the openings helps to prevent the fractures from closing when the injection is stopped.
Hydraulic fracturing helps remove natural gas and oil from rock formations deep within the earth's crust where there are insufficient porosity and permeability levels to allow these resources to flow from the reservoir to the wellbore at economic rates. In such case, the fractures preferably provide a conduit or path that connects the reservoir to the well, thereby increasing the area from which natural gas and liquids can be recovered.
The process used includes pumping the fracturing fluid into the wellbore at a rate sufficient to increase its pressure to above the fracture gradient of the rock formation. This pressure causes the rock formation to crack, allowing the fracturing fluid to enter and extend through the formations. To keep this fracture open after the injection stops, a proppant, such as sand, is often added to the fracture fluid. The propped hydraulic fracture then becomes a permeable conduit through which the fluid can flow.
Because drilling a borehole involves using a rotating drill bit, chips and particles of rock are often produced that can adversely affect the passage of fluid through the wellbore, resulting in reduced permeability and flow of fluid into the borehole. The borehole can also be sealed by the surrounding rock, wherein hydraulic fracturing can be used to increase the flow of fluid through the rock.
Various types of proppant, including sand, resin-coated sand, and man-made ceramics can be used depending on the desired permeability or grain strength. The injected fluid mixture is typically about 99% water and sand, although the fracture fluid can also be gel, foam, nitrogen, carbon dioxide or even air, etc.
In addition to the fluid, certain chemicals are often added to enhance the effectiveness of the fracturing i.e., the flow of natural gas to the surface. Thus, considerable environmental concerns have arisen, including the possibility that chemicals and other waste fluids might bleed into water aquifers, as well as the possible erosion and deformation that can result once fractures have been created and resources have been removed.
Environmental and health concerns associated with hydraulic fracturing include contamination of ground water, risks to air quality, the migration of gases and chemicals to the surface, the creation of seismic events, and the potential mishandling of waste. The potential costs associated with environmental clean-up, loss of land value, and human and animal health concerns are still being investigated and evaluated.
Hydraulic fracturing has favorably increased the production of natural gas from coal beds and shale rock formations in recent years. In the past, methane gas has been released during mining and post-mining activities, including various methane emissions which can be divided into the following categories:
Underground Mining: Methane gas can be removed from underground mines before and during mining by using degasification systems. The gas can be vented, flared (not currently done in the U.S.), or recovered for its energy content. Indeed, up to 50 to 60 percent of methane can typically be recovered from mines using degasification, wherein the remainder is released into the atmosphere. In underground mining, methane gas is often released into the mine shafts wherein methane is diluted into the ventilation air and then vented to the atmosphere.
Surface Mining: During surface mining, methane is typically released into the atmosphere as the overlying rock strata are removed, although for this type of release, no emissions mitigation options are currently being used. In theory, some pre-mining degasification and recovery could occur in certain surface mines. However, the low gas content of most surface mines relative to that of underground mines makes it unlikely that significant recovery would be technically feasible, let alone cost-effective.
Abandoned Mines: There are several thousand abandoned coal mines in the United States today. Of these, the EPA has identified some 400 that are considered “gassy.” Even though active mining no longer occurs, these mines can still produce significant methane emissions from diffuse vents, fissures, or boreholes, etc., which can be extracted and used to generate power, etc., although these emissions are not quantified or included in U.S. inventory estimates.
Coal mines already employ a range of technologies for recovering methane gas. These methods have been developed primarily for safety reasons, as a supplement to ventilation systems, to circulate dangerous methane gas from the mines. The major degasification technologies currently used in the U.S. include vertical wells, long-hole and short-hole horizontal boreholes, and gob wells. The quality of the gas extracted by these methods determines how they may be used. Vertical wells and in-mine horizontal boreholes produce nearly pure methane, while gob wells, which recover post-mining methane, typically recover methane mixed with air.
Even when degasification systems are used, mines still emit significant quantities of methane via ventilation systems. Technologies are in development that would catalytically oxidize the low concentrations of methane in ventilation air, producing usable thermal heat as a by-product. Methane recovered by degasification can be used for pipeline injection, power generation, on-site use in thermal coal drying facilities, or sold to nearby commercial or industrial facilities, etc. At present, most recovered coal mine methane is sold through natural gas pipelines.
Mines that are already recovering methane represent opportunities for utilities to work with mine operators to develop a use strategy. Utilities may also be able to participate in projects that are not currently recovering methane by implementing projects that include both gas recovery and utilization.
Coal bed gas formations or reservoirs often contain an orthogonal fracture set called cleats that are often oriented perpendicular to the bedding (which is nearly horizontal), which provide the primary conduit for upward fluid flow. Gas typically diffuses from the matrix into these cleats and flows up to the well bore. In coal bed gas reservoirs, the key parameters for controlling the amount of gas in place include coal bed thickness, coal composition, gas content, and gas composition. Coal composition refers to the amount and type of organic constituents found in the coal, which has a significant effect on the amount of gas that can be adsorbed and/or desorbed. Gas contents in coal seams vary widely (<1 to >25 m3/tonne) and are a function of coal composition, thermal maturity, burial and uplift history, and the addition of migrated thermal or biogenic gas. Note that 1 ton is 2,000 pounds and 1 tonne is 2,406.2 pounds. Gas composition is generally greater than 90% methane, with minor amounts of liquid hydrocarbons, carbon dioxide, and/or nitrogen.
Gas productivity from coal bed reservoirs is controlled primarily by the coal's permeability and the gas-saturation state. Permeability in producing areas typically ranges from a few millidarcies to a few tens of millidarcies, although permeabilities exceeding 1 Darcy have been reported. Absolute permeability increases with time as gas desorbs from the coal, causing the matrix to shrink and the cleats to widen, although this may be offset by a reduction in cleat aperture because of increased net stress caused by reservoir-pressure depletion.
Permeability is a key factor for coal bed methane (CBM) recovery. Coal beds are typically low in permeability, and almost all the permeability is usually due to fractures, which in coal beds are typically in the form of cleats and joints. Coal cleats are of two types: butt cleats and face cleats, which occur at nearly right angles. The face cleats are normally continuous and provide paths of higher permeability while butt cleats are usually non-continuous and end at face cleats.
Gas contained in coal beds are mainly methane and trace quantities of ethane, nitrogen, carbon dioxide and some other gases. Intrinsic properties of coal found in nature determine the amount of gas that can be recovered. The porosity of coal bed reservoirs is usually very small, ranging from 0.1 to 10%. The adsorption capacity of coal is defined as the volume of gas adsorbed per unit mass of coal usually expressed in SCF (standard cubic feet, the volume at standard pressure and temperature conditions) gas/ton of coal. The capacity to adsorb depends on the rank and quality of the coal. The adsorption ranges from 100 to 800 SCF/ton for most coal seams found in the United States. Most of the gas in coal beds is in the adsorbed form.
The permeability that is produced from fractures acts as the major channel for gas to flow—the higher the permeability the higher the gas production. For most coal bed seams found in the United States, the permeability lies in the range of 0.1 to 50 millidarcies. The permeability changes with the stress applied to the formation. Coal displays a stress-sensitive permeability and this process plays an important role during stimulation and production operations.
Hydraulic fracturing can be used to enhance gas recovery from coal beds by increasing their permeability. Since methane is stored (adsorbed) over time on the micropores of the coal itself, and this storage capacity is a function of the amount of pressure that has been exerted on the coal surfaces, i.e., the higher the pressure the greater the storage potential, production or release of gas from the coal normally requires the reduction of pressure within the formation. This pressure reduction frees the methane molecules from the coal bed and allows upward gas migration.
Water/gas separators used for conventional gas production are often modified to accommodate copious amounts of “produced” water and associated coal fines (small particles of coal that can pollute the water). After hydrostatic pressure is reduced, methane gas can be desorbed from the coal and is then free to migrate through the permeable strata and fractures to an area of lower pressure, i.e., ideally into well bores that created the pressure reduction. Since water must be withdrawn to reduce the pressure and allow gas migration, the volume of gas produced tends to build from a low initial rate to a maximum rate several years after the onset of production. When reservoir pressure drops below 150 psi, the well is no longer considered economic. It is estimated that less than 50% of the coal bed methane in place can be economically recovered by reservoir pressure depletion strategy. Thus, in areas like the San Juan Basin, enhanced production techniques have been used.
Another enhancement technique available introduces nitrogen under high pressure through injector wells into individual coal beds. Nitrogen sorption displaces the methane on the coal molecules and reduces the partial pressure of the methane. Beginning in the 1980's, some companies have experimented with this technique and found that up to 80% of the methane can be recovered with this strategy.
Gas bearing shale and tight sands are also making an emergence due to the application of newer technologies such as horizontal drilling and advanced stimulation methods including hydraulic fracturing. In this application we are not considering oil shale; we are considering gas shale. Oil shale is a term used to cover a wide range of fine-grained, organic-rich sedimentary rocks. Oil shale does not contain liquid hydrocarbons or petroleum as such but organic matter derived mainly from aquatic organisms. This organic matter, kerogen, may be converted to oil through destructive distillation or exposure to heat. The recovered organic fraction is then distilled, or pyrolyzed to produce the following products: crude shale oil, flammable hydrogen gas, and char.
Gas shale is productive in releasing natural gas when the surface area is exposed to other elements such as carbon dioxide. The greater the exposed surface area, the greater the efficiency and speed at which the gas is desorbed and released from the surface. Indeed, when gas shale is exposed to carbon dioxide, and carbon dioxide is adsorbed, methane gas (that has been adsorbed into the shale over time) will be desorbed and released.
Coals are sedimentary rocks containing more than 50 wt % organic matter, whereas gas shale contains less than 50 wt % organic matter. Methane is generated from the transformation of organic matter by bacterial (biogenic gas) and geochemical (thermogenic gas) processes during burial. The gas is stored by multiple mechanisms including free gas in the micropores and joints, and adsorbed gas on the internal surfaces of the organic matter. Nearly all coal bed gas is considered to be adsorbed gas, whereas gas shale is a combination of adsorbed gas and free gas. Free gas is the methane that is trapped within the pores or joints of the shale or coal structure.
True gas shale has adsorbed gas on the surfaces of the organic content, just like coal, as well as some free gas in the pore spaces and joints, unlike coal, which has virtually no macro-porosity. In such case, adsorbed gas is proportional to the total organic carbon (TOC) of the gas shale, and free gas is proportional to the effective porosity and gas saturation in the pores of the formation.
Gas shale has become an increasingly important source of natural gas in the United States, and interest has spread to Canada and Europe. This is because gas shale is found in significant abundance in many areas of the world and can be processed relatively economically to produce natural gas using the above described hydraulic fracturing methods.
Typically, gas shale is a solid of low permeability, and therefore, gas production in commercial quantities requires fracturing to provide increased permeability. While some formations may contain natural fractures, for profitable production of natural gas from gas shale, modern technology is required, such as hydraulic fracturing and horizontal drilling, etc.
Shale that hosts economic quantities of natural gas has a number of common properties. They are rich in organic material, and are usually mature petroleum source rock in a thermogenic gas window. They are sufficiently brittle and rigid enough to maintain open fractures and some of the gas produced can be held in natural fractures, some in pore spaces, and some adsorbed onto the surface of the organic material. The gas in the fractures can be released immediately, whereas, the gas adsorbed onto organic material is typically released as the formation pressure declines.
Because gas shale normally has insufficient permeability to allow significant fluid flow from the formation to the well bore, for gas shale to become a profitable source of natural gas, it is important that new technologies be developed to improve its permeability. In fact, with the advent of these new technologies, one analyst expects gas shale to supply as much as half the natural gas production in North America by 2020.
In gas shale formations, natural gas can sometimes be produced through more-permeable sand or silt layers inter-bedded with the shale, through natural fractures, or from the shale matrix itself. But in other cases, natural fractures are healed by a mineral filling and must be forced open by stimulation. It is also possible to have both shale and coal inter-bedded within a single reservoir, resulting in gas contributions from both lithologies.
In U.S. Pat. No. 7,264,049, issued to Maguire, entitled “In situ method of coal gasification,” an in-situ process for coal gasification using liquefied gases and combustion of the kerogen for heat release is provided. Maguire provides an in-situ process for coal gasification and the production of gas hydrates wherein a network of fractures is formed by injecting liquefied gases into a horizontally disposed fracturing borehole and allowing it to vaporize. The coal is thereafter ignited and the gases released by burning coal are recovered from the fractured formations. The crux of “Maguire” is a fracturing method that creates a large fracture system to apply heat to the coal reservoir, which consists of injecting large amounts of liquid nitrogen at very high rates into the horizontal fracturing boreholes.
One disadvantage of Maguire is that it uses combustion and heat to break up the formation and release gas from its fractures. In doing so, Maguire teaches using kerogen which is ignited within the formation to release the pressurized gas. Maguire's method is also used in coal beds, and does not specifically apply to gas shale.
U.S. Pat. No. 4,374,545, issued to Bullen, et al., entitled, “Carbon Dioxide Fracturing Process and Apparatus,” describes a method of fracturing in an underground stratigraphic formation that is penetrated by a borehole. Liquefied gas and a proppant are pumped into the formation via the borehole pipe to induce fractures in the formation and these fracture spaces are kept open by the proppant. Once injected, the liquid pressurized carbon dioxide is exposed to warmer temperatures, which causes the liquid to convert to a gas to induce further fracturing. The disadvantage of Bullen is that it uses proppants and chemicals that can raise environmental concerns.
One of the main contributors to global warming is believed to be the increase in carbon dioxide gas emitted into the earth's atmosphere by various man-made activities and technologies such as coal burning power plants. The main contributors to carbon dioxide emissions that can affect the earth's atmosphere and therefore increase global warming include solid fuels, such as coal, liquid fuels, such as gasoline, and gaseous fuels, such as natural gas. While there is strong motivation to use coal for the generation of energy due to its efficiency and abundance, there is also a strong interest in eliminating the undesired emission of carbon dioxide gas into the atmosphere which is caused by the combustion of coal in standard coal combustion power plants.
One of the existing technologies used to eliminate excess carbon dioxide emissions involves “capturing” the CO2 gas as it is being emitted from smokestacks, and storing it. The idea of carbon capture and storage (CCS)—first introduced in the 1970's—began by making use of existing underground reservoirs in which to store the CO2 gas. The available storage space in underground reservoirs is probably large enough to store all the carbon dioxide gas contained in all the remaining fossil fuel reserves throughout the world.
Recently, leading science and energy institutes advocated strongly for the further development of carbon capture and storage technology. For example, capturing CO2 from smokestacks for the purification of natural gas or at ammonia production facilities is a practice that has existed for years. Moreover, injection and storage of carbon dioxide gas is already occurring in the North Sea, Algeria, and Texas.
While some of these technologies have gained credibility in recent years, many experts still believe that because of the rapid use of the world's remaining fossil fuel supplies, it is necessary to further lower the environmental impact caused by these technologies in an effort to prevent catastrophic climate changes in the future. The problem at hand is that the process of capturing, transporting and storing carbon dioxide gas from coal combustion power plants can dramatically raise energy consumption costs and cause serious health and environmental issues and concerns. For example, if the energy used to capture CO2 emissions is derived directly from the fossil fuels themselves, the benefits of capturing and storing the CO2 will be offset by the very same energy intensive process. And, if the energy comes from renewable sources, the technology would be rendered unnecessary as it would be much more efficient to generate electricity directly from the renewable source.
Indeed, it has been discovered that capturing CO2 from smokestacks and compressing it for transport can be one of the most energy-intensive aspects of the process. According to the International Panel of Climate Change (IPCC), which prepared a comprehensive study, capturing technology (including compression of the gas for further transport and storage) can raise the energy consumption of a coal combustion power plant by an average of 32 percent.
Capturing carbon dioxide in rocks also requires a significant infrastructure that is comparable to today's coal industry, which can also lead to significant amounts of industrial wastes and mining tailings—for example, fuel ash from coal plants. The process also generates large amounts of waste materials (apart from the carbonised rocks themselves), and for every ton of carbon dioxide stored in rock, 2.87 to 45.18 tons of disposable materials would be created.
For all of the above reasons, a new and improved method and apparatus is needed for the capture and storage of CO2 gases emitted from coal combustion power plants, which can offset the high costs and disadvantages associated with current carbon dioxide extraction and removal methods, such that the world's coal reserves can be used without the consequences of adding to man-made global climate changes, and the high cost of producing energy. Moreover, for the above reasons, there is also a need to develop new and improved technologies for increasing the permeability of coal and gas shale formations to make better use of the world's supply of natural gas contained therein, including the gas stored in the pores and joints of the underground strata and adsorbed onto the surface of the rock formations, etc. Nevertheless, there is also a need to develop improved technologies that will avoid the use of chemicals and the production of waste materials, etc., that can be harmful to the environment.